1. Field of the Invention
Embodiments of the present disclosure generally relate to apparatuses and systems for distributing and feeding drilling material to a vibratory separator. In addition, embodiments disclosed herein relate to apparatuses and systems to maximize the efficiency of screening surfaces of vibratory separators.
2. Background Art
Oilfield drilling fluid, often called “mud,” serves multiple purposes in the industry. Among its many functions, the drilling mud acts as a lubricant to cool rotary drill bits and facilitate faster cutting rates. Typically, the mud is mixed at the surface and pumped downhole at high pressure to the drill bit through a bore of the drillstring. Once the mud reaches the drill bit, it exits through various nozzles and ports where it lubricates and cools the drill bit. After exiting through the nozzles, the “spent” fluid returns to the surface through an annulus formed between the drillstring and the drilled wellbore.
Furthermore, drilling mud provides a column of hydrostatic pressure, or head, to prevent “blow out” of the well being drilled. This hydrostatic pressure offsets formation pressures thereby preventing fluids from blowing out if pressurized deposits in the formation are breeched. Two factors contributing to the hydrostatic pressure of the drilling mud column are the height (or depth) of the column (i.e., the vertical distance from the surface to the bottom of the wellbore) itself and the density (or its inverse, specific gravity) of the fluid used. Depending on the type and construction of the formation to be drilled, various weighting and lubrication agents are mixed into the drilling mud to obtain the right mixture. Typically, drilling mud weight is reported in “pounds,” short for pounds per gallon. Generally, increasing the amount of weighting agent solute dissolved in the mud base will create a heavier drilling mud. Drilling mud that is too light may not protect the formation from blow outs, and drilling mud that is too heavy may over invade the formation. Therefore, much time and consideration is spent to ensure the mud mixture is optimal. Because the mud evaluation and mixture process is time consuming and expensive, drillers and service companies prefer to reclaim the returned drilling mud and recycle it for continued use.
Another significant purpose of the drilling mud is to carry the cuttings away from the drill bit at the bottom of the borehole to the surface. As a drill bit pulverizes or scrapes the rock formation at the bottom of the borehole, small pieces of solid material are left behind. The drilling fluid exiting the nozzles at the bit acts to stir-up and carry the solid particles of rock and formation to the surface within the annulus between the drillstring and the borehole. Therefore, the fluid exiting the borehole from the annulus is a slurry of formation cuttings in drilling mud. Before the mud can be recycled and re-pumped down through nozzles of the drill bit, the cutting particulates must be removed.
Apparatus in use today to remove cuttings and other solid particulates from drilling fluid are commonly referred to in the industry as “shale shakers.” A shale shaker, also known as a vibratory separator, is a vibrating sieve-like table upon which returning solids laden drilling fluid is deposited and through which clean drilling fluid emerges. Typically, the shale shaker is an angled table with a generally perforated filter screen bottom. Returning drilling fluid is deposited at the feed end of the shale shaker. As the drilling fluid travels down the length of the vibrating table, the fluid falls through the perforations to a reservoir below leaving the solid particulate material behind. The vibrating action of the shale shaker table conveys solid particles left behind until they fall off the discharge end of the shaker table. The above described apparatus is illustrative of one type of shale shaker known to those of ordinary skill in the art. In alternate shale shakers, the top edge of the shaker may be relatively closer to the ground than the lower end. In such shale shakers, the angle of inclination may require the movement of particulates in a generally upward direction. In still other shale shakers, the table may not be angled, thus the vibrating action of the shaker alone may enable particle/fluid separation. Regardless, table inclination and/or design variations of existing shale shakers should not be considered a limitation of the present disclosure.
Preferably, the amount of vibration and the angle of inclination of the shale shaker table are adjustable to accommodate various drilling fluid flow rates and particulate percentages in the drilling fluid. After the fluid passes through the perforated bottom of the shale shaker, it can either return to service in the borehole immediately, be stored for measurement and evaluation, or pass through an additional piece of equipment (e.g., a drying shaker, centrifuge, or a smaller sized shale shaker) to further remove smaller cuttings.
As drilling fluid is processed, residual drilling waste (e.g., high density fluids and particulate matter), may become stuck or entrained on the shaker screens and other internal shaker components. As the amount of residual drilling waste increases, the efficiency of the shale shaker may decrease due to, for example, clogged screens, clogged outlet lines, and/or “gummed up” internal components. To maintain shaker efficiency, the residual drilling waste must be removed from the shaker components.
Accordingly, there exists a need to increase the efficiency of shakers by reducing the amount of residual drilling waste that may clog up and entrain on the components of the shaker. Additionally, there exists a need to increase the efficiency of shakers by providing drilling material to multiple decks of a shaker, when provided, such that each deck of the shaker may be able to filter drilling fluid simultaneously.